Burst QAM downhole telemetry system

ABSTRACT

A downhole telemetry system that transmits a burst-QAM uplink signal to the surface of the well is disclosed. In a preferred embodiment, a downhole instrument coupled to a pair of conductors in a wireline or composite tubing string transmits a burst-QAM uplink signal to a surface system. The burst-QAM signal preferably comprises a series of data frames carrying telemetry data. Each data frame is preferably preceded by a quiet interval (when no signal is present), a timing synchronization sequence, and a training sequence. The timing synchronization sequence is designed for easy timing recovery at the surface, and the training sequence is designed to aid the adaptation of the equalizer. The data frame itself preferably includes a synchronization field, a data count, and a checksum in addition to the data. Direct digital synthesis is preferably employed to modulate the uplink signal.

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application is a continuation-in-part of U.S. patentapplication Ser. No. 09/599,343, filed Jun. 22, 2000, and entitled“Burst QAM Downhole Telemetry System” by inventors Michael Wei andWilliam Trainor.

BACKGROUND OF THE INVENTION

[0002] 1. Field of the Invention

[0003] The present invention relates to a telemetry system fortransmitting data from a downhole drilling assembly to the surface of awell. More particularly, the present invention relates to a system andmethod for signaling over information conduits coupled between adownhole transmitter and an uphole receiver.

[0004] 2. Description of the Related Art

[0005] Modem petroleum drilling and production operations demand a greatquantity of information relating to parameters and conditions downhole.Such information typically includes characteristics of the earthformations traversed by the wellbore, along with data relating to thesize and configuration of the borehole itself. The collection ofinformation relating to conditions downhole, which commonly is referredto as “logging”, can be performed by several methods.

[0006] In conventional oil well wireline logging, a probe or “sonde”housing formation sensors is lowered into the borehole after some or allof the well has been drilled, and is used to determine certaincharacteristics of the formations traversed by the borehole. The upperend of the sonde is attached to a conductive wireline that suspends thesonde in the borehole. Power is transmitted to the sensors andinstrumentation in the sonde through the conductive wireline. Similarly,the instrumentation in the sonde communicates information to the surfaceby electrical signals transmitted through the wireline.

[0007] The problem with obtaining downhole measurements via wireline isthat the drilling assembly must be removed or “tripped” from the drilledborehole before the desired borehole information can be obtained. Thiscan be both time-consuming and extremely costly, especially insituations where a substantial portion of the well has been drilled. Inthis situation, thousands of feet of tubing may need to be removed andstacked on the platform (if offshore). Typically, drilling rigs arerented by the day at a substantial cost. Consequently, the cost ofdrilling a well is directly proportional to the time required tocomplete the drilling process. Removing thousands of feet of tubing toinsert a wireline logging tool can be an expensive proposition.

[0008] As a result, there has been an increased emphasis on thecollection of data during the drilling process. Collecting andprocessing data during the drilling process eliminates the necessity ofremoving or tripping the drilling assembly to insert a wireline loggingtool. It consequently allows the driller to make accurate modificationsor corrections as needed to optimize performance while minimizing downtime. Designs for measuring conditions downhole including the movementand location of the drilling assembly contemporaneously with thedrilling of the well have come to be known as“measurement-while-drilling” techniques, or “MWD”. Similar techniques,concentrating more on the measurement of formation parameters, commonlyhave been referred to as “logging while drilling” techniques, or “LWD”.While distinctions between MWD and LWD may exist, the terms MWD and LWDoften are used interchangeably. For the purposes of this disclosure, theterm MWD will be used with the understanding that this term encompassesboth the collection of formation parameters and the collection ofinformation relating to the movement and position of the drillingassembly.

[0009] When oil wells or other boreholes are being drilled, it isfrequently necessary or desirable to determine the direction andinclination of the drill bit and downhole motor so that the assembly canbe steered in the correct direction. Additionally, information may berequired concerning the nature of the strata being drilled, such as theformation's resistivity, porosity, density and its measure of gammaradiation. It is also frequently desirable to know other downholeparameters, such as the temperature and the pressure at the base of theborehole, for example. Once this data is gathered at the bottom of theborehole, it is typically transmitted to the surface for use andanalysis by the driller.

[0010] Sensors or transducers typically are located at the lower end ofthe drill string in LVVD systems. While drilling is in progress thesesensors continuously or intermittently monitor predetermined drillingparameters and formation data and transmit the information to a surfacedetector by some form of telemetry. Typically, the downhole sensorsemployed in MWD applications are positioned in a cylindrical drillcollar that is positioned close to the drill bit. The MWD system thenemploys a system of telemetry in which the data acquired by the sensorsis transmitted to a receiver located on the surface. There are a numberof telemetry systems in the prior art which seek to transmit informationregarding downhole parameters up to the surface without requiring theuse of a wireline cable. Of these, the mud pulse system is one of themost widely used telemetry systems for MWD applications.

[0011] The mud pulse system of telemetry creates “acoustic” pressuresignals in the drilling fluid that is circulated under pressure throughthe drill string during drilling operations. The information that isacquired by the downhole sensors is transmitted by suitably timing theformation of pressure pulses in the mud stream. The information isreceived and decoded by a pressure transducer and computer at thesurface.

[0012] In a mud pressure pulse system, the drilling mud pressure in thedrill string is modulated by means of a valve and control mechanism,generally termed a pulser or mud pulser. The pulser is usually mountedin a specially adapted drill collar positioned above the drill bit. Thegenerated pressure pulse travels up the mud column inside the drillstring at the velocity of sound in the mud. Depending on the type ofdrilling fluid used, the velocity may vary between approximately 3000and 5000 feet per second. The rate of transmission of data, however, isrelatively slow due to pulse spreading, distortion, attenuation,modulation rate limitations, and other disruptive forces, such as theambient noise in the drill string. A typical pulse rate is on the orderof a pulse per second (1 Hz).

[0013] Given the recent developments in sensing and steeringtechnologies available to the driller, the amount of data that can beconveyed to the surface in a timely manner at 1 bit per second is sorelyinadequate. As one method for increasing the rate of transmission ofdata, it has been proposed to transmit the data using vibrations in thetubing wall of the drill string rather than depending on pressure pulsesin the drilling fluid. However, the presence of existing vibrations inthe drill string due to the drilling process severely hinders thedetection of signals transmitted in this manner.

SUMMARY OF THE INVENTION

[0014] Accordingly, there is disclosed herein a downhole telemetrysystem that transmits a burst-QAM uplink signal to the surface of thewell. In a preferred embodiment, a downhole instrument coupled to a pairof conductors transmits a burst-QAM uplink signal to a surface systemsimilarly coupled to the pair of conductors. The burst-QAM signalpreferably comprises a series of data frames carrying telemetry data.Each data frame is preferably preceded by a quiet interval (when nosignal is present), a timing synchronization sequence, and a trainingsequence. The timing synchronization sequence is designed for easytiming recovery at the surface, and the training sequence is designed toaid the adaptation of the equalizer. The data frame itself preferablyincludes a synchronization field, a data count, and a checksum inaddition to the data. Direct digital synthesis is preferably employed tomodulate the uplink signal.

BRIEF DESCRIPTION OF THE DRAWINGS

[0015] A better understanding of the present invention can be obtainedwhen the following detailed description of the preferred embodiment isconsidered in conjunction with the following drawings, in which:

[0016]FIG. 1 is a schematic view of an oil well in which the telemetrysystem may be employed;

[0017]FIG. 2A is an isometric schematic of a composite tubing sectionhaving helically wound information conduits contained within;

[0018]FIG. 2B is an isometric view of a tubing section having a wirelinecable contained within;

[0019]FIG. 3 is a schematic of the circuits that couple the telemetrysignals to the tubing;

[0020]FIG. 4 is a functional block diagram of a surface computer system;

[0021]FIG. 5 is a functional block diagram of a downhole communicationsmodule in the supervisory sub;

[0022]FIG. 6 is an exemplary implementation of an uplink telemetry dataframe;

[0023]FIG. 7 is a functional block diagram of an uplink telemetrytransmitter;

[0024]FIG. 8 is a functional block diagram of an uplink telemetryreceiver;

[0025]FIG. 9 is a schematic view of a wireline system in which thetelemetry system may be employed;

[0026]FIG. 10 shows a cross-section of a seven-conductor wireline cable;and

[0027]FIG. 11 shows a cross-section of a single-conductor wirelinecable.

[0028] While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and will herein be described in detail. Itshould be understood, however, that the drawings and detaileddescription thereto are not intended to limit the invention to theparticular form disclosed, but on the contrary, the intention is tocover all modifications, equivalents and alternatives falling within thespirit and scope of the present invention as defined by the appendedclaims.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

[0029] Turning now to the figures, FIG. 9 shows a well during wirelinelogging operations. A drilling platform 902 is equipped with a derrick904 that supports a hoist 906. Drilling of oil and gas wells is commonlycarried out by a string of drill pipes connected together by “tool”joints so as to form a drilling string that is lowered through a rotarytable 912 into a wellbore 914. In FIG. 9, the drilling string has beentemporarily removed from the wellbore 914 to allow a sonde 916 to belowered by wireline 908 into the wellbore 914. Typically, the sonde 916is lowered to the bottom of the region of interest and subsequentlypulled upward at a constant speed. During the upward trip, the sonde 916performs measurements on the formations 919 adjacent to the wellbore asthey pass by. The measurement data is communicated to a logging facility920 for storage, processing, and analysis. In an alternative situation(e.g. a highly deviated or horizontal well), a threaded or continuoustubing string may be employed to convey the sonde through the hole. Inthis circumstance the wireline may be run through the interior of thetubing string or attached to the exterior of the tubing string.

[0030]FIG. 10 shows a cross-section of a typical wireline cable havingmultiple conductors 1002. Each of the conductors is surrounded by aninsulating jacket 1004. The insulated conductors may be bundled togetherin a poorly-conductive wrap 1005, which is surrounded by two layers ofcounterwound metal armor wire 1006. Being made of metal, the armor wiresare conductive and may be used as an eighth conductor. In wirelinelogging of cased and cemented wells, a single conductor logging cablesuch as that shown in FIG. 11 may be preferred. The single conductorcable typically has a single, multi-stranded conductor 1102 encased ininsulative material 1104 and wound within a fabric liner 1106 which isin turn wound within a double layer of counter wound metal armor wires1108. Power and telemetry are typically conveyed together on a singlecable. In single conductor cables, the power is generally transmitted asa low frequency signal, whereas the telemetry signal(s) are transmittedin a higher frequency band. In multi-conductor cables, the signalisolation is further improved by the use of orthogonal transmissionmodes. Orthogonal modes and the circuitry therefor are discussed in muchgreater detail in co-pending application Ser. No. 09/437,594, entitled“High-Power Well Logging Method And Apparatus” by inventors G. Baird, C.Dodge, T. Henderson and F. Velasquez, which is hereby incorporatedherein by reference.

[0031] Accordingly, there are at least two methods for establishing acommunications channel for downhole communications. One of severalorthogonal transmission modes may be used to carry the telemetry signalon a multiconductor cable, or a single conductor cable may be used tocarry the telemetry signal in the normal fashion. FIG. 1 shows a thirdmethod that employs conductors embedded in the walls of compositetubing.

[0032]FIG. 1 shows a well having a spool 102 of composite or steeltubing 104 being injected into a wellbore by an injector 106. The tubing104 is injected through a packer 108 and a blowout preventer 110, andpasses through casing 112 into the wellbore. In the well, a downholeinstrument 114 may be coupled to the composite tubing 104 and configuredto communicate to a surface computer system 116 via information conduitsembedded contained in the composite tubing 104. Alternatively for steeltubing 104, the downhole instrument may be configured to communicate tothe surface computer system 116 via a wireline cable contained in theinterior of the tubing 104. A power supply 118 may be provided to supplypower to downhole instrument 114 via power conduits in composite tubing104 or wireline cable.

[0033] Surface computer system 116 is configured to communicate withdownhole instrument 114. Downhole instrument 114 may, for example, be asupervisory sub for a bottom-hole drilling assembly. The sub may becoupled to downhole sensors and/or control devices configurable tomeasure and set, respectively, downhole parameters. Examples of sensorsinclude temperature, pressure, density, and flow-rate sensors. Examplesof control devices include valves, variable-aperture ports, heaters, andartificial lift devices.

[0034] Surface computer system 116 is preferably configured by software120 to monitor and control downhole instrument 114. System 116 mayinclude a display device-122 and a user-input device 124 to allow ahuman operator to interact with the system control software 120.

[0035] An isometric representation of composite tubing 104 is shown inFIG. 2A. As the name suggests, composite tubing 104 is a tube havingwalls 202 made primarily of a composite material such as, e.g.fiberglass or carbon fiber, although other suitable materials are knownand contemplated. Conduits 204 may be embedded in the walls of compositetubing. To reduce the probability of conduit breakage, the conduits arepreferably wound helically around the tubing bore within the walls ofthe composite tubing. The winding angle is preferably a function of thestress coefficient differential between the conduit material and thecomposite material.

[0036] In a preferred embodiment, the conduits 204 contained in thecomposite tubing are electrical conductors, although one or more of theconduits may alternatively be optical fibers or hydraulic conduits.Preferably, six circumferentially-spaced conductors are provided, withtwo adjacent conductors dedicated to carrying telemetry signals. Theelectrical conductors for carrying telemetry in the wireline cable maysimilarly be replaced with telemetry conduits of different form, suchas, for example, optical fibers or hydraulic conduits.

[0037] An isometric view of steel tubing 104 is shown in FIG. 2B. Inthis instance, a wireline cable is shown extending through the interiorof the tubing. This reduces the possibility of conduit breakage fromabrasion or “pinching” of the cable in the wellbore. The informationconduits may be electrical or optical conductors.

[0038]FIG. 3 shows one circuit configuration which allows the uplinktelemetry signal to share electrical conductors with the downlinktelemetry signal. In the downhole portion of the coupling circuitconfiguration, an isolation transformer 302 preferably couples thetelemetry signal conductors of the wireline or tubing to the downholeinstrument. A center-tapped secondary winding has one terminal endcoupled to a high pass filter (HPF) 304 via a transmit resistance R_(T),and the other terminal end coupled to a low pass filter (LPF) 306 with ashunt resistance R_(R) to ground. The center tap is coupled to groundvia an impedance block 308 for impedance matching purposes.

[0039] HPF 304 blocks signals below the uplink signal cutoff frequency,thereby preventing any uplink signal energy from interfering with thedownlink signal. The uplink signal energy is screened off from thedownlink signal by LPF 306, which blocks any signal energy above thecutoff frequency of the downlink signal.

[0040] It is noted that the energy of the uplink and downlink signals isexpected to be comparable downhole. This is not the case at the surface,where the downlink signal energy is expected to be substantially greaterthan the uplink signal energy. To prevent the downlink signal fromoverwhelming the uplink signal detectors, a bridge arrangement is usedin the uphole portion of the coupling circuit configuration.

[0041] The surface portion of the coupling circuit configurationpreferably uses an isolation transformer 310 to couple to the telemetrysignal conductors of the wireline or tubing. One terminal of thesecondary winding is coupled to ground, while the other terminal iscoupled to a transmit signal node 312 via a resistance R. A matchingimpedance 314 also has one terminal coupled to ground and the otherterminal coupled to node 312 via a second, identical resistance R. Thedownlink signal is provided to node 312 via a low pass filter 316 and apower amplifier 318. The downlink signal voltage on node 312 causessimilar currents to flow in the two branches, with a small differencecaused by the uplink signal. This uplink signal difference can bedetected in the form of a voltage difference between the intermediatenodes of the branches. A differential amplifier 320 amplifies thisdifference and provides it to a high pass filter 322 for filtering. Thediscrimination of the high pass filter 322 in filtering out the downlinksignal is aided by the common mode rejection of the differentialamplifier.

[0042] Although a specific coupling circuit configuration has beendescribed, it is recognized that other coupling techniques may be used.Other suitable “4-wire to 2-wire” coupling configurations are known inthe art and may be used. Alternatively, the uplink and downlink signalsmay be carried on separate sets of conductors, or may be transformedinto optical signals or pressure signals for other conduit types.

[0043]FIG. 4 shows one embodiment of surface computer system 116 (whichmay be contained in surface facility 920). System 116 includes a centralprocessing unit 402 coupled to a system memory 404 via a bridge 406.System memory 404 stores software 408 for execution by processor 402.Bridge 406 also couples processor 402 to a peripheral bus 410.Peripheral bus 410 supports the transfer of data to and from theprocessor 402. Peripheral devices connected to peripheral bus 410 canthereby provide the processor 402 with access to the outside world. Inthe shown embodiment, a signal conditioning board 412 and a digitaldecoder board 414 are coupled to the peripheral bus 410.

[0044] Signal conditioning board 412 is also coupled to the telemetryconduits. Downlink data that the processor 402 wishes to send to thedownhole instrument 114 is provided to bus interface logic 422 of thesignal conditioning board 412. The interface logic 422 handlescompliance with the bus protocol and extracts the downlink data from thebus signals to be provided to frequency-shift key (FSK) modulator 424.FSK modulator 424 converts the data into an analog downlink signal whichis then provided to LPF 316 to screen out any high frequency components.Isolation transformer 310 puts the downlink signal onto the telemetryconduits and extracts the uplink signal, passing it to HPF 322 whichscreens out any low frequency components. The uplink signal is amplifiedby amplifier 432 and provided to an analog-to-digital converter (ADC)442 on digital decoder card 414.

[0045] ADC 442 preferably provides the digitized signal to a digitalsignal processor (DSP) 444 for filtering and decoding. DSP 444 isconfigured by software to perform bandpass or matched filtering 446 andequalization and timing recovery 448 to extract the uplink data symbols.The data symbols are decoded 450 and the decoded uplink data is providedto processor 402 for analysis. Details of the uplink telemetry signalformat and decoding will be discussed further below.

[0046]FIG. 5 shows one embodiment of the downhole instrument telemetrymodule. A DSP 502 is configured by software to format and encode 504uplink data for transmission to the surface. The encoded digital data ispreferably modulated in quadrature amplitude modulation (QAM) form by adirect digital synthesis (DDS) chip 506 to provide an analog uplinksignal. The analog uplink signal is high pass filtered 304 and providedto isolation transformer 302. Isolation transformer couples the uplinksignal to the telemetry conduits and couples the downlink signal fromthe telemetry conduits to low pass filter 306. LPF 306 screens out thesignal energy above the cutoff frequency, and a demodulator 508 convertsthe downlink signal into digital baseband form for decoding by DSP 502.

[0047] In a preferred embodiment, the downlink signal is a FSK modulatedsignal using the 2.4-9.6 kHz frequency band. This signal is preferablyused to transmit commands and configuration parameters to the downholeinstrument. The uplink signal is preferably a burst-QAM modulated signalusing the 16-48 kHz frequency band. This signal is preferably used totransmit measurement data to the surface.

[0048] The DSP may optionally be a chip from the ADSP-2100 Family of DSPMicrocomputers manufactured and sold by Analog Devices, a company doingbusiness in Norwood, Mass. The DDS chip may optionally be an AD7008 CMOSDDS Modulator manufactured and sold by the same company.

[0049] It is noted that the uplink link preferably employs burst-QAM toachieve increased channel capacity without a commensurate increase inreceiver complexity. In one embodiment, the burst-QAM communication isdone in the form of uplink data frames 602, each frame being preceded bya quiet interval 604 and a timing synchronization sequence 606, as shownin FIG. 6. An equalization training sequence 608 may also be providedimmediately before the data frame 602. It is contemplated that theuplink communication be done in terms of 16-bit words, each of which aretransmitted as four 4-bit (16-QAM) symbols. The quiet interval 604 iscontemplated to be 30 words (120 symbol periods), the timing sequence606 is contemplated to be 20 words (80 symbols), the training sequence608 to be 126 words (504 symbols), and the frame 602 to be a maximum of1024 words (4096 symbols). It is recognized, however, that otherconfigurations may also be suitable. For example, other word lengths maybe employed, and the QAM constellation may be made larger (e.g. 32, 64,128, 256, 512, 1024, or more constellation points), or smaller (i.e. 2,4, or 8 constellation points).

[0050] Data frame 602 preferably begins with two synchronization words,a data count word, up to 1020 words of data, and ends with a checksumword. The data count word preferably indicates the number of data words.The number of data words per frame may be adjusted according to systemrequirements and according to a desired rate of recurrence of theresynchronization and re-training sequences. For example, if the numberof data words per frame is 1020 in the above described embodiment, thetiming resynchronization and retraining will occur over 10 times persecond. However, in some conditions it may be desired to increase theresynchronization frequency to over 20 times per second. This may beachieved by reducing the number of data words per frame to about 512.Alternatively, the number of bits per QAM symbol may be increased toreduce the number of symbols per frame.

[0051]FIG. 7 shows, in functional block form, the uplink signal transmitpath 700. In block 702 the data frame 602 is “scrambled” by bit-by-bitXOR-ing it with a pseudorandom sequence. The pseudorandom sequence is aneasily reproduced mask which “randomizes” the data frame to removepredictable, periodic patterns that often occur in measurement data.Such patterns, if not removed, may cause undesirable spectral lines thatinterfere with adaptive equalization in the receiver.

[0052] The scrambled data is then, in block 704, divided into symbolsthat are mapped to signal points in the QAM constellation. In block 706,the symbols are modulated onto a carrier frequency, filtered andamplified in block 710, and coupled to the telemetry conduits. Apreamble generator block 708 is shown parallel to the data path.Preamble generator 708 generates the quiet period 604, timingsynchronization sequence 606, and training sequence 608, and insertsthem into the transmit signal ahead of each data frame. Referringmomentarily to FIG. 5, blocks 702 and 704 may be part of encodersoftware 504, blocks 706 and 708 may be implemented by the DDS chip 506,and block 710 may be implemented by HPF 304.

[0053]FIG. 8 shows, in functional block form, the uplink signal receivepath 800. In block 802, the signal received from the telemetry conduitsis filtered to screen out signal energy below the uplink signal cutofffrequency. The uplink signal is then digitized in block 804, andmatch-filtered in block 806 to maximize the signal-to-noise ratio. Inblock 808, a timing recovery algorithm operates to lock the receivertiming to the timing synchronization sequence. In block 810, the uplinksignal is equalized to correct for channel effects. During theequalization of the training sequence, knowledge of the trainingsequence is used to adapt the equalizer to the telemetry channel. Theequalizer consequently exhibits improved equalization performance on thedata frame. The equalizer output is a sequence of QAM symbols. In block812, the symbol sequence is converted to a 16-bit word sequence, withproper alignment achieved from knowledge of the training sequence. Block814 blocks the extraneous words from the quiet interval, the timingsequence, and the training sequence, and passes on only the data frame.In block 816, the scrambling operation is reversed, the check sumverified, and the data count, along with the data words, provided asoutput. Referring momentarily to FIG. 4, block 802 corresponds to block322, block 804 to block 442, block 806 to block 446, blocks 808 and 810to block 448, and blocks 812-816 to block 450.

[0054] The exemplary embodiments described above provide for telemetrythrough conduits in wireline and composite tubing. In the case ofelectrical conductors in composite tubing, the telemetry channel isexpected to have a range of up to 50,000 ft with an attenuation of 40-45dB in the frequency ranges under consideration. The framing structureemployed in burst-QAM signaling is expected to provide regularlyrecurring opportunities for timing resynchronization and equalizerretraining. This is expected to significantly improve the reliability ofthe uplink channel.

[0055] It is noted that the telemetry system disclosed herein may havemultiple applications, including, for example, smart wells. Smart wellsare production wells that may have sensors and controllable mechanismsdownhole. The sensors may, for example, be used to detect density andflow rates. An uphole system may use this information to operate thecontrollable mechanisms (e.g. variable aperture ports and heaters orother artificial lift mechanisms) to optimize the production of thewell.

[0056] Numerous variations and modifications will become apparent tothose skilled in the art once the above disclosure is fully appreciated.It is intended that the following claims be interpreted to embrace allsuch variations and modifications.

1. A method of communicating telemetry information comprising: groupingdata words to form data frames; transmitting a preamble before each dataframe; and transmitting the data frames immediately after the respectivepreamble.
 2. The method of claim 1, wherein the preamble includes aquiet interval.
 3. The method of claim 1, wherein the preamble includesa timing synchronization sequence.
 4. The method of claim 1, wherein thepreamble includes a training sequence.
 5. The method of claim 1, whereinthe act of transmitting the data frames includes using quadratureamplitude modulation to impress the data onto a carrier signal.
 6. Themethod of claim 1, further comprising: prepending a synchronization wordand a data word count to each group of data words; and appending achecksum to each group of data words.
 7. The method of claim 6, furthercomprising: scrambling each group of data words by combining the groupof data words with a mask.
 8. The method of claim 1, further comprising:receiving the preambles; generating a local clock signal that issynchronized with a timing synchronization sequence in the preambles;and updating coefficients of an adaptive filter using a trainingsequence in the preambles.
 9. A telemetry transmitter comprising: ascrambler configured to exclusive-or data frames with a mask; a preamblegenerator configured to provide a preamble before each data frame; amodulator coupled to the preamble generator to receive the preambles andcoupled to the scrambler to receive scrambled data frames, wherein themodulator is configured to modulate the preambles and scrambled dataframes to form a quadrature amplitude modulated (QAM) signal, whereinthe preamble is identical from frame to frame.
 10. The telemetrytransmitter of claim 9, wherein the preamble includes: a quiet interval;a timing synchronization sequence; and a training sequence.
 11. Thetelemetry transmitter of claim 9, further comprising: a high pass filterconfigured to block low-frequency components of the QAM signal; and anisolation transformer configured to couple the filtered QAM signal totelemetry conductors contained within composite tubing. 12-30.(canceled)